Within the oil and gas industry, the continuing search for and exploitation of oil and gas reservoirs has resulted in the development of directionally drilled exploration and production well boreholes, that is boreholes which extend away from vertical and which permit the borehole to extend into the reservoir to a greater extent. By extending the step-out distance from a fixed location such as an offshore platform, the high angle or horizontal section of the borehole passes through the producing formation, thereby maximising the surface area of the borehole in contact with the producing formation while also assisting in minimising water ingress. In this way, the production rate or quantity of the oil or gas being produced may be enhanced since the borehole is able to reach oil or gas which would otherwise be bypassed by a vertical or near vertical borehole.
Directionally drilled boreholes are now being drilled deeper, longer and higher in angle (from vertical) than previously, with boreholes now being drilled horizontally for considerable distances. Indeed, in some cases the horizontal step out from the position of the surface location of the drilling site may be as much as 11 kilometers.
The drilling and/or completion of a high angle or horizontal borehole presents a number of problems not present in vertical or near vertical wells.
For example, completion of a high angle or horizontal pre-drilled bore may incur problems resulting from the fact that the tubulars forming the running or completion string tend to lie on the low side of the bore, resulting in torque, drag and wear to the string and/or the surrounding bore-lining tubulars, typically casing or liner. In some cases, the extensive running and rotating of the tubulars through the horizontal cased section of the borehole can cause such severe wear to the wall of the casing that the casing pressure integrity is compromised. This may require that the completion be withdrawn (where indeed this is possible) or other remedial work or workover carried out, resulting in significant expense and delay to the operator.
Similarly, in the case of the drilling horizontal and high angle boreholes, the drill string itself will typically lie on the low side of the borehole wall, resulting in increased wear to the drill string, associated components and/or damage to the borehole.
The drilling of high angle and horizontal boreholes, while effective, may also suffer from a number of further performance reducing factors. For example, in order to create any borehole, it is necessary to exert sufficient force on the drill bit to enable the drill bit to drive through rock, known as weight on bit. In today's horizontal and high angle borehole drilling, the current method using rotary drilling equipment is for the weight on bit to be provided by the downward gravitational force of the portion of the drill string situated in the upper, vertical or lower angle (nearer to vertical) section of the borehole. This downward gravitational force, which is generally provided by heavy weight drilling tubulars, such as heavy weight drill pipe, is transmitted in the form of compression through the rotating drilling tubulars to the portion of the drill string situated in the lower, high angle or horizontal section of the borehole in order to apply the necessary weight on bit. However, it will be recognized that for boreholes having a significant non-vertical section, a major percentage of the drilling tubulars forming the lower portion of the drill string, which would normally contribute to the weight on bit in a vertical borehole, are unable to contribute to the weight on bit.
Also, compression applied to a long string of rotating drilling tubulars in a borehole tends to cause a degree of buckling and pipe whirl, forcing the rotating tubulars against the bore wall and again creating increased longitudinal friction, rotational friction and wear to the drilling tubulars.
Similar issues may also occur in running completion tools and assemblies into pre-existing boreholes.
Some of these factors can be mitigated by the provision of spacers known as stabilisers situated at strategic positions and in sufficient numbers along the drill string. However, the stabilisers themselves introduce a number of negative factors when applied in high angle and horizontal drilling or completion.
Drilling stabilisers typically fall into two main categories: fixed blade stabilisers and non-rotating stabilisers. Fixed blade stabilisers have a body for coupling to the drill string and, as their name implies, one or more blades either fixed to the body or formed as an integral part of the body. The blades, which are typically formed in a spiral to increase borehole wall contact, rotate with the drill string or completion string to which they are attached. By centralising the tubulars in the borehole and reducing wellbore wall contact, fixed blade stabilisers may address or mitigate the buckling or whirling effects of applied compressive loads. However, because the stabiliser blades by design remain in contact with the borehole wall and because friction is independent of area, fixed blade stabilisers do little to reduce the effect of rotational friction in the high angle or horizontal sections of the borehole where most of the weight of the drilling tubulars are now being supported by the stabiliser blades on the low side of the borehole.
It may be argued that by reducing the contact between the drill string and the borehole wall, stabilisers assist in keeping the drill string or completion string moving and, by virtue of the fact that dynamic friction of the stabiliser blade rotating against the borehole wall is lower than static friction, thus reduce longitudinal friction. However, the dynamic friction component remains and must also be overcome by the compressive forces applied through the tubulars, for example drilling tubulars, from higher up the borehole. This residual longitudinal dynamic friction component has to be considered as an unavoidable but detrimental factor associated with the use of fixed blade stabilisation in high angle and horizontal boreholes.
As in the case of fixed blade stabilisers, non-rotating stabilisers have a body for coupling to the drill string or completion string. However, in non-rotating stabilisers the stabiliser blades are attached to or are integral with a sleeve provided around the body. A bearing is provided between the outside of the body and the inside of the sleeve so that, in use, the sleeve and body are relatively rotatable (the sleeve is non-rotating relative to the rotating body and drill string). The main benefit of this type of stabiliser, besides centralising the rotating drilling tubulars, is to substantially reduce the rotational friction effect experienced by conventional fixed blade stabilisers. This is achieved by the bearing between the rotating tool body and the non-rotating sleeve being very much more efficient than the fixed blade stabiliser blades rotating against the inside diameter of the bore. However, the fact that the non-rotating stabiliser sleeve is effectively static with respect to the wall of the bore and given that static friction is higher than dynamic friction, this introduces a secondary negative factor that has a detrimental effect known as stick slip.
Stick slip is caused by the forces required to overcome the longitudinal static friction component of the non-rotating stabiliser blades in contact with the borehole wall when moving the drilling tubulars forward or down to apply more weight to the drill bit. These forces put the drilling tubulars, between the drill bit and the drilling tubulars higher up the bore that provide the applied force, into further compression like a compression spring so that when the lower section of drilling tubulars start to move to overcome the longitudinal static friction component, and because static friction is higher than dynamic friction, they do so in a “stick slip” fashion. For example, the drilling tubulars that form the lower part of the drill string and drilling assembly which are being supported and centralised by these non-rotating stabilisers stick initially, as the drilling tubulars are lowered or moved forward in order to apply further weight to the drill bit, and then slip driven by the compressed tubulars above them, once the static friction component is overcome, applying weight on bit in an uncontrollable manner.
Both rotational and longitudinal friction are major detrimental factors which reduce rotational input power and the ability to control applied weight on bit in high angle and horizontal rotary drilling applications, reducing the rate at which the borehole can be progressed and substantially increasing the cost to complete the bore, as well as the possibility of causing damage, and reduced life, to the drill bit.
In addition to the issues described above when drilling the borehole, if it is ever desired to move the drill string or running string or completion string in a reverse direction, that is out of hole, similar issues with friction may arise. Pulling the string out of a borehole having a high angle or horizontal section may suffer from a further problem in that the vertical pull force exerted on the string causes the curved portion of the string situated around the heel of the borehole to contact the upper wall of the borehole, known as the capstan effect. This may make it difficult or even impossible to pull the string out of the borehole.